CALGARY, ALBERTA–(Marketwired – Nov. 10, 2016) – Canacol Energy Ltd. (“Canacol” or the “Corporation”) (TSX:CNE)(OTCQX:CNNEF)(BVC:CNEC) is pleased to report its financial and operating results for the three and nine months ended September 30, 2016. Dollar amounts are expressed in United States dollars, except as otherwise noted.
“The three months ended September 30, 2016 marked yet another consecutive quarter of production growth for Canacol,” reported Charle Gamba, President and CEO of Canacol. “During the third quarter, Canacol achieved record realized contractual sales volumes of 18,908 boepd, an 11% increase over the average of 17,017 boepd for the previous quarter ended June 30, 2016. Adjusted funds from operations for the three months ended September 30, 2016 increased 14% to $30.7 million from the previous quarter of $26.9 million for the three months ended June 30, 2016.
“We were also able to increase our corporate operating netbacks for the third consecutive quarter, to $25.83 per boe.
“The August, 2016 $36 million private placement allowed us to expand our gas exploration and development program by contracting a second gas rig for the remainder of 2016, and we plan to have at least one gas drilling rig running continuously well into 2017. Since this private placement, we have announced new gas discoveries at both Nispero and Trombon, which tested at 28 MMscfpd and 26 MMscfpd, respectively, and we look forward to further success at Nelson-6, Nelson-8 and Clarinete-3 which are all expected to be drilled prior to year end. We also plan to drill one oil exploration well on our VMM-2 concession in December, 2016.”
Highlights for the three and nine months ended September 30, 2016
(Production is stated as working-interest before royalties)
Financial and operational highlights of the Corporation include:
- Realized contractual sales volumes increased 76% and 47% to 18,908 boepd and 15,727 boepd for the three and nine months ended September 30, 2016, respectively, compared to 10,727 boepd and 10,692 boepd for the same periods in 2015, respectively, primarily due to increase in gas production in Esperanza and VIM-5 as a result of the additional sales related to the Promigas pipeline expansion.
- Average production volumes increased 78% and 47% to 18,632 boepd and 15,342 boepd for the three and nine months ended September 30, 2016, respectively, compared to 10,455 boepd and 10,455 boepd for the same periods in 2015, respectively, primarily due to increase in gas production in Esperanza and VIM-5 as a result of the additional sales related to the Promigas pipeline expansion.
- Adjusted funds from operations for the three and nine months ended September 30, 2016 increased 102% and 67% to $30.7 million and $71 million compared to the same periods in 2015, respectively. Adjusted funds from operations are inclusive of results from the Ecuador IPC. The increase in adjusted funds from operations is primarily the result of additional sales related to the Promigas pipeline expansion, reductions in production and transportation expenses and lower general and administrative expenses, offset by a decrease in benchmark crude oil prices.
- Total petroleum and natural gas revenues for the three and nine months ended September 30, 2016 increased 102% and 40% to $44.4 million and $106 million compared to $22 million and $75.7 million for same periods in 2015, respectively. Adjusted petroleum and natural gas revenues, inclusive of revenues related to the Ecuador Incremental Production Contract (the “Ecuador IPC”) (see full discussion in MD&A), for the three and nine months ended September 30, 2016 increased 70% and 30% to $50.9 million and $125.2 million compared to $29.9 million and $96.6 million for the same periods in 2015, respectively. The increase in revenues reflects the additional sales related to the Promigas pipeline expansion, offset by a decrease in benchmark crude oil prices.
- General and administrative (“G&A”) expenses decreased 2% and 16% to $4.8 million and $12.7 million for the three and nine months ended September 30, 2016, respectively, compared to $4.9 million and $15.2 million for the same periods in 2015, respectively. The decrease is primarily due to the Corporation’s efforts to manage its G&A expenses in light of the continued weakness in benchmark crude oil.
- Production expenses decreased 28% and 49% to $4.6 million and $12.3 million for the three and nine months ended September 30, 2016, respectively, compared to $6.4 million and $24.1 million for the same periods in 2015, respectively, despite significant production increases in the three and nine months ended September 30, 2016 compared to the same periods in 2015. The decrease is primarily due to the Corporation’s cost-cutting initiatives and lower crude oil production. The increase in natural gas production did not increase production expenses significantly as the majority of the natural gas production expenses are fixed.
- The Corporation had a comprehensive loss of $8.4 million and a comprehensive income of $3.3 million for the three and nine months ended September 30, 2016, respectively, compared to a comprehensive loss of $19 million and $93.2 million for the same periods in 2015, respectively. The $8.4 million comprehensive loss in the three months ended September 30, 2016 was mainly driven by the $14.6 million non-cash impairment as a result of the relinquishment of two blocks in Colombia.
- During the three months ended September 30, 2016, the Nispero‐1 exploration well was completed and tested at 28 MMscfpd of dry gas with no water. With success at Nispero-1, on September 13, 2016, the Corporation spud the Trombon‐1 exploration well from the same drilling platform the Nispero-1 well was drilled from. The Trombon‐1 exploration well targets the same CDO reservoir interval tested in the offsetting Nispero‐1 well, but in a distinct and isolated fault block located approximately 2 kilometers south of the Nispero-1 discovery. On October 17, 2016, the Trombon-1 exploration well was completed and tested at 26 MMscfpd of dry gas with no water. Both the Nispero-1 and Trombon-1 wells are tied into the Corporation’s operated Jobo production facility.
- Net capital expenditures including acquisitions for the three and nine months ended September 30, 2016 was $28.7 million and $49.3 million, respectively, while adjusted capital expenditures including acquisitions, inclusive of amounts related to the Ecuador IPC, was $29.2 million and $50.5 million, respectively.
- At September 30, 2016, the Corporation had $62.1 million in cash and $62.6 million in restricted cash and continues to be well within all of its banking covenants.
|Financial||Three months ended
|Nine months ended
|Total petroleum and natural gas revenues, net of royalties||44,392||21,958||102||%||106,018||75,684||40||%|
|Adjusted petroleum and natural gas revenues, net of royalties, including revenues related to the Ecuador IPC(2)||50,851||29,899||70||%||125,241||96,602||30||%|
|Cash provided by operating activities||22,275||14,302||56||%||43,288||1,386||>999||%|
|Per share – basic ($)||0.13||0.11||18||%||0.27||0.01||>999||%|
|Per share – diluted ($)||0.13||0.11||18||%||0.26||0.01||>999||%|
|Adjusted funds from operations (1) (2)||30,719||15,218||102||%||71,040||42,499||67||%|
|Per share – basic ($)||0.18||0.12||50||%||0.44||0.36||22||%|
|Per share – diluted ($)||0.18||0.12||50||%||0.43||0.35||23||%|
|Net (loss) income and comprehensive (loss) income||(8,399||)||(19,029||)||(56||%)||3,307||(93,191||)||n/a|
|Per share – basic ($)||(0.05||)||(0.15||)||(67||%)||0.02||(0.78||)||n/a|
|Per share – diluted ($)||(0.05||)||(0.15||)||(67||%)||0.02||(0.78||)||n/a|
|Capital expenditures, net, including acquisitions||28,698||22,299||29||%||49,292||113,716||(57||%)|
|Adjusted capital expenditures, net, including acquisitions and capital expenditures related to the Ecuador IPC (1)(2)||29,208||26,080||12||%||50,533||125,751||(60||%)|
|Working capital surplus, excluding non-cash items (1)||68,524||46,310||48||%|
|Common shares, end of period (000s)||172,976||159,266||9||%|
|Operating||Three months ended
|Nine months ended
|Petroleum and natural gas production, before royalties (boepd)|
|Petroleum and natural gas sales, before royalties (boepd)|
|Realized contractual sales, before royalties (boepd)|
|Ecuador tariff oil (2)||1,711||2,156||(21||%)||1,728||1,875||(8||%)|
|Operating netbacks ($/boe) (1)|
|Esperanza (natural gas)||27.63||22.54||23||%||27.45||22.55||22||%|
|VIM-5 (natural gas)||24.65||–||n/a||24.52||–||n/a|
|Ecuador (tariff oil) (2)||38.54||38.54||–||38.54||38.54||–|
|(1)||Non‐IFRS measure – see “Non‐IFRS Measures” section within MD&A.|
|(2)||Inclusive of amounts related to the Ecuador IPC – see “Non-IFRS Measures” section within MD&A.|
|(3)||Includes tariff oil production and sales related to the Ecuador IPC.|
The three months ended September 30, 2016 was another record quarter for the Corporation in terms of production levels, and its highest revenues, EBITDAX, and adjusted funds flows from operations since the robust oil prices of 2014; primarily due to having a full quarter of increased gas production as a result of the completion of the Promigas pipeline expansion in April 2016 which allowed the Corporation to increase average daily gas cash sales to approximately 90 MMscfpd.
In August of 2016, the Corporation accepted a $36 million equity financing, which was completed at a premium to the existing market price. The proceeds of which have been used to accelerate the Corporation’s 2016 gas exploration and development program. The objective of the program is to continue building the reserve base to sign a new ten year 100 MMscfpd ship or pay gas pipeline and gas sales contracts, which are anticipated to commence in 2018 after the construction of a new pipeline, as well as the drilling of two additional development wells to add additional productive capacity. The Corporation is currently negotiating several new long term take or pay gas sales contracts with existing and new clients, as well as a contract which will see a third party construct and operate a new pipeline to the Caribbean coast of Colombia operational in late 2018, at no cost to the Corporation.
Looking ahead to the remainder of 2016, the Corporation’s resource capture strategy anticipates four more wells before year end. The Corporation has contracted the Tuscany Rig‐12 to drill the Nelson-6 gas exploration well and the Nelson-8 gas development well. Tuscany Rig‐15 mobilized from the Trombon discovery to the Clarinete field and spud the Clarinete-3 gas development well on November 3, 2016. The Nelson-6 exploration well was spud on October 18, 2016 and is targeting interpreted gas pay within the shallow Porquero sandstone reservoir in the Nelson field. Existing Nelson wells drilled to date have encountered up to 62 feet of interpreted gas pay on open-hole logs over the Porquero sandstone reservoir. Upon testing and completion of the Nelson-6 exploration well, the Corporation will drill the Nelson-8 development well targeting productive reservoirs within the CDO reservoir that are not being drained by the existing producing wells in the Nelson field. A third rig, the Tuscany Rig-14 has been contracted to drill the Mono Capuchino‐1 oil exploration well on the VMM-2 E&P contract located in the Middle Magdalena Basin. The well is anticipated to be spud on December 1, 2016 and is expected to take up to two months to drill and test.
Canacol estimates that average net before royalty oil and gas production for 2016 will range between 16,000 and 17,000 boepd. Realized contractual gas sales will average approximately 75 MMscfpd (13,160 boepd) including approximately 90 MMscfpd from April 21, 2016 forward at an anticipated average realized price of $5.60/Mcf ($31.92/boe), with an average netback of approximately $4.56/Mcf ($26.00/boe). Additionally, Canacol anticipates Colombian oil production to average approximately 2,300 bopd and Ecuador oil production of approximately 1,300 bopd in calendar 2016, both without the drilling of any additional oil wells. Total corporate hydrocarbon sales are anticipated to average between 18,500 and 19,000 boepd for the last half of 2016.
Total corporate EBITDAX is anticipated to be approximately $135 million for calendar 2016, which represents a Consolidated Leverage Ratio of less than 2.0, despite realized contractual gas sales for the period of January 1, 2016 to April 20, 2016 being less than half of current volumes.
The Corporation is in active negotiations to refinance its existing debt consisting of the BNP Senior Secured Term Loan and the Apollo Senior Notes, currently totaling $255 million, into a single term loan facility, with the intention to a) lower the average interest rate, and b) extend the first amortization payment of the new term loan into 2019.
This press release should be read in conjunction with the Corporation’s unaudited interim condensed consolidated financial statements and related Management’s Discussion and Analysis. The Corporation’s has filed its unaudited interim condensed consolidated financial statements and related Management’s Discussion and Analysis as of and for the three and nine months ended September 30, 2016 with Canadian securities regulatory authorities. These filings are available for review on SEDAR at www.sedar.com.
Canacol is an exploration and production company with operations focused in Colombia and Ecuador. The Corporation’s common stock trades on the Toronto Stock Exchange, the OTCQX in the United States of America, and the Colombia Stock Exchange under ticker symbols CNE, CNNEF, and CNEC, respectively.
This press release contains certain forward-looking statements within the meaning of applicable securities law. Forward-looking statements are frequently characterized by words such as “plan”, “expect”, “project”, “target”, “intend”, “believe”, “anticipate”, “estimate” and other similar words, or statements that certain events or conditions “may” or “will” occur, including without limitation statements relating to estimated production rates from the Corporation’s properties and intended work programs and associated timelines. Forward-looking statements are based on the opinions and estimates of management at the date the statements are made and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. The Corporation cannot assure that actual results will be consistent with these forward looking statements. They are made as of the date hereof and are subject to change and the Corporation assumes no obligation to revise or update them to reflect new circumstances, except as required by law. Information and guidance provided herein supersedes and replaces any forward looking information provided in prior disclosures. Prospective investors should not place undue reliance on forward looking statements. These factors include the inherent risks involved in the exploration for and development of crude oil and natural gas properties, the uncertainties involved in interpreting drilling results and other geological and geophysical data, fluctuating energy prices, the possibility of cost overruns or unanticipated costs or delays and other uncertainties associated with the oil and gas industry. Other risk factors could include risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities, and other factors, many of which are beyond the control of the Corporation. Other risks are more fully described in the Corporation’s most recent Management Discussion and Analysis (“MD&A”) and Annual Information Form, which are incorporated herein by reference and are filed on SEDAR at www.sedar.com. Average production figures for a given period are derived using arithmetic averaging of fluctuating historical production data for the entire period indicated and, accordingly, do not represent a constant rate of production for such period and are not an indicator of future production performance. Detailed information in respect of monthly production in the fields operated by the Corporation in Colombia is provided by the Corporation to the Ministry of Mines and Energy of Colombia and is published by the Ministry on its website; a direct link to this information is provided on the Corporation’s website. References to “net” production refer to the Corporation’s working-interest production before royalties.
Use of Non-IFRS Financial Measures – Due to the nature of the equity method of accounting the Corporation applies under IFRS 11 to its interest in the Ecuador IPC, the Corporation does not record its proportionate share of revenues and expenditures as would be typical in oil and gas joint interest arrangements. Management has provided supplemental measures of adjusted revenues and expenditures, which are inclusive of the Ecuador IPC, to supplement the IFRS disclosures of the Corporation’s operations in this press release. Such supplemental measures should not be considered as an alternative to, or more meaningful than, the measures as determined in accordance with IFRS as an indicator of the Corporation’s performance, and such measures may not be comparable to that reported by other companies. This press release also provides information on adjusted funds from operations. Adjusted funds from operations is a measure not defined in IFRS. It represents cash provided by operating activities before changes in non-cash working capital and decommissioning obligation expenditures, and includes the Corporation’s proportionate interest of those items that would otherwise have contributed to funds from operations from the Ecuador IPC had it been accounted for under the proportionate consolidation method of accounting. The Corporation considers adjusted funds from operations a key measure as it demonstrates the ability of the business to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Adjusted funds from operations should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with IFRS as an indicator of the Corporation’s performance.
The Corporation’s determination of adjusted funds from operations may not be comparable to that reported by other companies. For more details on how the Corporation reconciles its cash provided by operating activities to adjusted funds from operations, please refer to the “Non-IFRS Measures” section of the Corporation’s MD&A. Additionally, this press release references working capital, EBITDAX and operating netback measures. Working capital is calculated as current assets less current liabilities, excluding non-cash items, and is used to evaluate the Corporation’s financial leverage. EBITDAX is defined as consolidated net income adjusted for interest, income taxes, depreciation, depletion, amortization, exploration expenses, share of joint venture profit/loss and other similar non-recurring or non-cash charges. Consolidated EBITDAX is further adjusted for the contribution to adjusted funds from operations, before taxes, of the results of the Ecuador IPC. Operating netback is a benchmark common in the oil and gas industry and is calculated as total petroleum and natural gas sales, less royalties, less production and transportation expenses, calculated on a per barrel of oil equivalent basis of sales volumes using a conversion. Operating netback is an important measure in evaluating operational performance as it demonstrates field level profitability relative to current commodity prices. Working capital, EBITDAX and operating netback as presented do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities.
Operating netback is defined as revenues less royalties and production and transportation expenses.
Realized contractual gas sales is defined as gas produced and sold plus gas revenues received from nominated take or pay contracts.
Total cash sales is defined as realized contractual gas sales and crude oil sales plus cash received for gas classified as deferred income according to IFRS.
Unrisked recoverable resource potential is based on management’s estimates.
Boe Conversion – The term “boe” is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet of natural gas to barrels oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this news release, we have expressed boe using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Ministry of Mines and Energy of Colombia. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 5.7:1, utilizing a conversion on a 5.7:1 basis may be misleading as an indication of value.
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